Packer element protection from incompatible fluids

ABSTRACT

Protective elements are placed over packer seal elements to provide insulation from incompatible wellbore fluids and its degrading effects. The protective element may take the form of an insulating tape, a protective coating, a sleeve, or a tube fitted over the packer seal element.

FIELD OF THE INVENTION

The present invention relates generally to downhole equipment and, more specifically, to a packer element protected from incompatible fluids.

BACKGROUND

Downhole packers are commonly used in many oilfield applications for the purpose of sealing against the flow of fluid to isolate one or more portions of a wellbore for the purposes of testing, treating, or producing the well. Non-limiting examples of fluid include: liquids such as oil and water, gases such as natural gas, and three-phase flow. The packers are suspended in the wellbore, or in a casing in the wellbore, from a tubing string, or the like, and are activated, or set, so that one or more packer elements engage the inner surface of the wellbore or casing, thus preventing fluid flow through the annulus.

Retrievable packer elements are compounded from a very limited number of different rubber compounds. This is primarily due to the fact that elastomers capable of handling a wide variety of oil field fluids normally have low tensile strength and low extrusion resistance. Such strength qualities are needed for retrievable packer elements. Therefore, most packer elements are made from tough Nitrile (e.g., NBR and HNBR) materials as they have good extrusion resistance. However, the Nitrile does not have good chemical compatibility resistance with many common oil field completion fluids, such as Zinc Bromide, also referred to as incompatible fluids. As a result, when Nitrile is used in these environments, the packer element begins degrading as soon as it comes into contact with the incompatible fluid. For example, in some fluid environments, the packers only last 24 hours. However, the time required to perform certain operations (such as tripping and setting a packer for a drill string test) can far exceed 24 hours. As a result, costly retrieval and resetting operations are regularly required.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a well system having two packer elements positioned therein, which may embody principles of the present disclosure;

FIG. 2 is an exploded view of packer element 18,20 of FIG. 1, according to certain illustrative embodiments of the present disclosure;

FIG. 3 is an illustration of a packer element wrapped with protective tape; and

FIG. 4 is a cross-sectional view of a packer assembly having a protective sleeve, according to certain illustrative embodiments of the present disclosure.

DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS

Illustrative embodiments and related methods of the present invention are described below as they might be employed in a packer element protected from incompatible fluids. In the interest of clarity, not all features of an actual implementation or method are described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure. Further aspects and advantages of the various embodiments and related methods of the disclosure will become apparent from consideration of the following description and drawings.

As described herein, illustrative embodiments of the present disclosure are directed to packer elements having a protective element positioned thereon which protects the packer's rubber compound from incompatible wellbore fluids. In general, the protective element protects the packer element from the incompatible fluid until the packer is set. The protective element may take a variety of forms. In a first embodiment, protective tape is wrapped around the packer element. In a second embodiment, a layer of fluid compatible rubber is applied in the packer element. In a third embodiment, a protective coating is painted on the packer element. In a fourth embodiment, a selectively actuatable sleeve is applied to the workstring over the packer element. In a fifth embodiment, a tub is placed over the packer element. In a sixth embodiment, a bag is placed over the packer element. Accordingly, through use of the protective elements, the life of the packer element in the incompatible fluid is extended since the packer element is not exposed to the fluids until after setting.

FIG. 1 is a well system having two packer elements positioned therein, which may embody principles of the present disclosure. In well system 10, a tubular string 12 (e.g., a production tubing string, liner string, etc.) has been installed in wellbore 14. Wellbore 14 may be fully or partially cased (as depicted with casing string 16 in an upper portion of FIG. 1), and/or wellbore 14 may be fully or partially uncased (as depicted in a lower portion of FIG. 1). An annular barrier is formed between tubular string 12 and casing string 16 by means of a packer element 18. Another annular barrier is formed between tubular string 12 and uncased wellbore 14 by means of another packer element 20.

It should be clearly understood that packer elements 18,20 are merely two examples of practical uses of the principles of the present disclosure. Other types of packer elements may be constructed, and other types of annular barriers may be formed, without departing from the principles of the invention. For example, an annular barrier could be formed in conjunction with a tubing, liner or casing hanger, a packer may or may not include an anchoring device for securing a tubular string, a bridge plug or other type of plug may include an annular barrier, etc. Thus, the embodiments described herein are not limited in any manner to the details of well system 10.

Each of the packer elements 18, 20 includes a seal assembly which engages the corresponding wall; however, for simplicity the complete packer assembly will be represented herein as packer elements 18,20. The seal assembly of the packer element may be, for example, an inflatable packer assembly. Various techniques may be employed for expanding the packer element into contact with the corresponding wall, as will be understood by those ordinarily skilled in the art having the benefit of this disclosure.

As previously mentioned, the illustrative embodiments described herein apply protective elements to insulate the packer elements from degrading downhole fluids. FIG. 2 is an exploded view of packer element 18,20 of FIG. 1, according to certain illustrative embodiments of the present disclosure. As shown in FIG. 2, packer element 18,20 is a seal assembly 22 having a protective element 24 placed over it. Protective element 24 insulates packer element 18,20/seal assembly 22 from wellbore fluids during deployment of the workstring 12 into the wellbore. In certain embodiments, after packer element 18,20 is set along casing string 16, protective element 24 is damaged such that seal assembly 22 is then exposed to wellbore fluids and degradation begins. In other embodiments, however, even after setting of packer element 18,20, protective element 24 remains intact such seal assembly 22 continues to be insulated from the wellbore fluids.

Protective element 24 may take a variety of embodiments. In a first embodiment, protective element 24 is protective tape wrapped around seal assembly 22. The tape may be, for example, a self-amalgamating tape, which may take the form of a non-tacky silicone-rubber tape which, when stretched and wrapped around seal assembly 22 in a continuous fashion, combines or unites itself into a strong, seamless, rubbery, waterproof, and electrically insulating layer. As packer element 18,20 is run into the wellbore, seal assembly 22 is not exposed to the incompatible wellbore fluid. The silicone rubber in the protective tape is compatible with most oil field completion fluids and, thus, insulates/protects the Nitrile seal assembly 22 from exposure. When packer element 18,20 is set in certain embodiments, the silicone rubber tape 24 would no longer fully protect the Nitrile seal 22 from the fluid, and the degrading of packer element 18,20 would finally start. One advantage of this embodiment is that the silicone rubber tape 24 may be applied to the packer element in the field whenever it is determined the well bore fluid is incompatible with the seal assembly 22. FIG. 3 is an illustration of an illustrative packer element 18,20 wrapped with protective tape 24.

Still referencing FIG. 2, in a second embodiment, protective element 24 may take the form of a layer of wellbore fluid compatible rubber applied to seal assembly 22. In this embodiment, seal assembly 22 would be manufactured, then the protective wellbore fluid-compatible rubber layer 24 would be overlaid atop the entire seal assembly 22. The inner core/seal assembly 22 would still be the tough Nitrile, but the outer layer would be the protective wellbore fluid compatible rubber.

In a third embodiment, the protective element 24 is a protective coating painted on packer element 18,20. Here, a protective coating is painted all exterior surfaces of seal assembly 22. Examples of such paint include, for example, flexible paints used to coat inflatable boats and other formulations that have different compatibility in different fluids. Other examples include car bumper paint, truck bed liner paints, Plastidip® and Flexseal®.

In a fourth embodiment, protective element 24 takes the form of a selectively actuatable sleeve positioned over packer element 18,20. FIG. 4 is a cross-sectional view of a packer assembly having a protective sleeve, according to certain illustrative embodiments of the present disclosure. In FIG. 4, a spring loaded sleeve 26 is installed over packer elements 18,20 and compatible fluid is placed inside cavity 30 formed between packer elements 18,20 and sleeve 26. In this illustrative embodiment, sleeve 26 is deactivated by the initial packer setting process, which would shear pins 32, thus allowing spring 28 to fully uncover the packer elements.

To provide a more detailed description, FIG. 4 is provided. In this example, a complete packer assembly 19 is illustrated. Packer assembly 19 may be any variety of packer assembly, such as, for example, the RTTS™ packer commercially available from Halliburton Energy Services, Inc. of Houston, Tex. USA. However, other types of packers may be used along the workstring, in keeping with the spirit of this disclosure. Examples of other packers which may be used include the CHAMP IV™ and CHAMP V™ packers, also marketed by Halliburton Energy Services, Inc.

Nevertheless, packer assembly 19 is representative of a retrievable packer, operation of which can benefit from the principles of this disclosure. Packer assembly 19 includes a generally tubular mandrel 34, a set of hydraulically actuated slips 36, a set of seal assemblies 22, a set of mechanically actuated slips 40 and a drag block 42. A J-slot mechanism (not shown) controls whether mandrel 34 can be lowered (as viewed in FIG. 4) relative to the seal assemblies 22, slips 40 and drag block 42. Drag block 42 is biased into contact with an inner wall of the casing 16 (FIG. 1) (or the formation wall 14 in an uncased wellbore) and thereby provides a frictional force, so that mandrel 34 will displace downward relative to the seal assemblies 22, slips 40 and drag block when the J-slot mechanism is operated to its “set” position.

As stated above, a selectively actuatable sleeve 26 is positioned over seal assemblies 22 and biased using spring 28. Fluid compatible with seal assemblies 22 is pumped into cavity 30 (formed between packer elements 18,20 and sleeve 26) just before the workstring is deployed downhole. Since wellbore fluid is already in the wellbore, once packer assembly 19 comes into contact with the wellbore fluid, the compatible fluid in cavity 30 will remain in place due to hydrostatic pressure present in the wellbore. As the compatible fluid is held in place, it insulates seal assemblies 22 from the wellbore fluid.

To set the packer assembly 19 in one illustrative method, the packer assembly is positioned lower in the wellbore than its intended setting location. Packer assembly 19 is then raised and rotated to select the J-slot mechanism “set” position, and the tubular string 12/mandrel 34 is then lowered to set seal assemblies 22. The frictional force provided by drag block 42 urges slips 40 upward along ramps 44, so that slips 40 displace radially outward and obtain an initial “bite” into casing 16 (or the formation wall if the wellbore is uncased). However, in doing so, slips 40 first shear the pins 32, thus releasing sleeve 26 to move in the direction of spring 28 until sleeve 26 abuts shoulder 29. As a result, seal assemblies 22 are no longer insulated from the wellbore fluids. Thereafter, further lowering of the tubular string 12 and mandrel 34 compresses the seal assemblies 22, thereby radially outwardly extending the seal elements and sealing off the annulus. After being set, packer assembly 19 can be unset by raising the mandrel 34, thereby decompressing the seal assemblies 22 and allowing slips 40 to retract inward.

In a fifth embodiment, the protective element is a tube placed around seal assembly 22. For example, a thin metal tube could be installed over the seal assemblies, thus keeping them isolated from the incompatible wellbore fluid. When the packer element 18,20 is set, the tube would be forced out into the casing, as previously described. In such an embodiment, the metallic nature of the tube may enable it to remain intact after setting, thus continuing to insulate the seal assembly.

In a sixth embodiment, the protective element is an expandable tube placed around the seal assembly 22. Here, for example, a thin Teflon® or plastic tube could be installed over the seal elements 22. Depending on the material selected, the tube would either expand with the seals 22 (thus, continuing to insulate from incompatible fluids) or may break up into many pieces.

In a seventh embodiment, the protective element is a bag placed over the seal assembly 22. Here, for example, a plastic or Teflon® bag may be custom fit to the seal assembly 22. In other embodiments, the bag may have a continuous zip-lock type sealing method, thus allowing for more efficient application to the seal assembly.

All of the methods describes herein may be used alone or combined with one another to extend the life of the packer elements in incompatible wellbore fluids. In certain embodiments, exposure to the incompatible wellbore fluid does not begin until after the packer is set. In other embodiments, the protective elements continue to protect the packer elements even after setting, thus extending the useful life even more.

Accordingly, the embodiments described herein greatly increase the useful life of packer elements. Earlier attempts to extend the useful life molded the entire packer element from fluid compatible materials; however, the disadvantage to such techniques was that the fluid compatible material had a low extrusion resistance that greatly reduced the pressure holding capability of the packer. As a result, the prior art approaches produced poor performing packers. However, in the illustrative embodiments described herein, protection from incompatible fluids is achieved while maintaining the pressure holding capabilities of state-of-the-art packers.

Embodiments and methods of the present disclosure described herein further relate to any one or more of the following paragraphs:

1. A packer element protection method, comprising: deploying a workstring along a wellbore, the workstring having a packer element thereon, wherein a protective element is positioned over the packer element; insulating the packer element from wellbore fluids using the protective element; and setting the packer element.

2. A method as defined in paragraph 1, wherein the packer element is insulated using a protective tape wrapped around the packer element.

3. A method as defined in paragraphs 1 or 2, wherein the packer element is insulated using a layer of fluid compatible rubber placed over the packer element.

4. A method as defined in any of paragraphs 1-3, wherein the packer element is insulated using a protective coating painted on the packer element.

5. A method as defined in any of paragraphs 1-4, wherein the packer element is insulated using a selectively actuatable sleeve positioned over the packer element.

6. A method as defined in any of paragraphs 1-5, wherein setting the packer element comprises actuating the sleeve to uncover the packer element and setting the packer element.

7. A method as defined in any of paragraphs 1-6, wherein the packer element is insulated using a tube positioned over the packer element.

8. A method as defined in any of paragraphs 1-7, wherein setting the packer element comprises expanding the tube along with the packer element or breaking the tube when the packer element is set.

9. A method as defined in any of paragraphs 1-8, wherein the packer element is insulated using a bag positioned over the packer element.

10. A method as defined in any of paragraphs 1-9, further comprising exposing the packer element to the wellbore fluids after the packer element is set.

11. A method of constructing a protected packer element, comprising applying a protective element over a packer element; and positioning the packer element on a workstring.

12. A method as defined in paragraph 11, wherein applying the protective element comprises wrapping the packer element with a protective tape.

13. A method as defined in paragraphs 11 or 12, wherein applying the protective element comprises applying a layer of fluid compatible rubber to the packer element.

14. A method as defined in any of paragraphs 11-13, wherein applying the protective element comprises painting a protective coating on the packer element.

15. A method as defined in any of paragraphs 11-14, wherein applying the protective element comprises positioning a selectively actuatable sleeve over the packer element.

16. A method as defined in any of paragraphs 11-15, wherein protecting the packer element comprises placing a tube over the packer element.

17. A method as defined in any of paragraphs 11-16, wherein applying the protective element comprises applying an expandable tube over the packer element.

18. A method as defined in any of paragraphs 11-17, wherein applying the protective element comprises placing a bag over the packer element.

19. A protected packer element, comprising a packer element; and a protective element placed over the packer element, wherein the protective element insulates the packer element from wellbore fluids.

20. A packer element as defined in paragraph 19, wherein the protective element is a protective tape wrapped around the packer element.

21. A packer element as defined in paragraphs 19 or 20, wherein the protective element is a layer of fluid compatible rubber applied to the packer element.

22. A packer element as defined in any of paragraphs 19-21, wherein the protective element is a protective coating painted on the packer element.

23. A packer element as defined in any of paragraphs 19-22, wherein the protective element is a selectively actuatable sleeve positioned over the packer element.

24. A packer element as defined in any of paragraphs 19-23, wherein the protective element is a tube placed around the packer element.

25. A packer element as defined in any of paragraphs 19-24, wherein the tube is an expandable tube.

26. A packer element as defined in any of paragraphs 19-25, wherein the protective element is a bag placed over the packer element.

27. A packer element as defined in any of paragraphs 19-26, wherein the protective element is no longer insulates the packer element from the wellbore fluids after the packer element is set.

The foregoing disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Further, spatially relative terms, such as “beneath,” “below,” “lower,” “above,” “upper” and the like, may be used herein for ease of description to describe one element or feature's relationship to another element(s) or feature(s) as illustrated in the figures. The spatially relative terms are intended to encompass different orientations of the apparatus in use or operation in addition to the orientation depicted in the figures. For example, if the apparatus in the figures is turned over, elements described as being “below” or “beneath” other elements or features would then be oriented “above” the other elements or features. Thus, the illustrative term “below” can encompass both an orientation of above and below. The apparatus may be otherwise oriented (rotated 90 degrees or at other orientations) and the spatially relative descriptors used herein may likewise be interpreted accordingly.

Although various embodiments and methods have been shown and described, the invention is not limited to such embodiments and methods and will be understood to include all modifications and variations as would be apparent to one skilled in the art. Therefore, it should be understood that the invention is not intended to be limited to the particular forms disclosed. Rather, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the invention as defined by the appended claims. 

1. A packer element protection method, comprising: deploying a workstring along a wellbore, the workstring having a packer element thereon, wherein a protective element is positioned over the packer element; insulating the packer element from wellbore fluids using the protective element; and setting the packer element.
 2. A method as defined in claim 1, wherein: the packer element is insulated using a protective tape wrapped around the packer element; the packer element is insulated using a layer of fluid compatible rubber placed over the packer element; the packer element is insulated using a protective coating painted on the packer element; or the packer element is insulated using a selectively actuatable sleeve positioned over the packer element.
 3. (canceled)
 4. (canceled)
 5. (canceled)
 6. A method as defined in claim 2, wherein setting the packer element comprises: actuating the sleeve to uncover the packer element; and setting the packer element.
 7. A method as defined in claim 1, wherein the packer element is insulated using a tube positioned over the packer element.
 8. A method as defined in claim 7, wherein setting the packer element comprises: expanding the tube along with the packer element; or breaking the tube when the packer element is set.
 9. A method as defined in claim 1, wherein the packer element is insulated using a bag positioned over the packer element.
 10. A method as defined in claim 1, further comprising exposing the packer element to the wellbore fluids after the packer element is set.
 11. A method of constructing a protected packer element, comprising: applying a protective element over a packer element; and positioning the packer element on a workstring.
 12. A method as defined in claim 11, wherein applying the protective element comprises: wrapping the packer element with a protective tape; applying a layer of fluid compatible rubber to the packer element; painting a protective coating on the packer element; positioning a selectively actuatable sleeve over the packer element; or placing a tube over the packer element.
 13. (canceled)
 14. (canceled)
 15. (canceled)
 16. (canceled)
 17. A method as defined in claim 11, wherein applying the protective element comprises applying an expandable tube over the packer element.
 18. A method as defined in claim 11, wherein applying the protective element comprises placing a bag over the packer element.
 19. A protected packer element, comprising: a packer element; and a protective element placed over the packer element, wherein the protective element insulates the packer element from wellbore fluids.
 20. A packer element as defined in claim 19, wherein the protective element is a protective tape wrapped around the packer element.
 21. A packer element as defined in claim 19, wherein the protective element is a layer of fluid compatible rubber applied to the packer element.
 22. A packer element as defined in claim 19, wherein the protective element is a protective coating painted on the packer element.
 23. A packer element as defined in claim 19, wherein the protective element is a selectively actuatable sleeve positioned over the packer element.
 24. A packer element as defined in claim 19, wherein the protective element is a tube placed around the packer element.
 25. A packer element as defined in claim 24, wherein the tube is an expandable tube.
 26. A packer element as defined in claim 19, wherein the protective element is a bag placed over the packer element.
 27. A packer element as defined in claim 19, wherein the protective element is no longer insulates the packer element from the wellbore fluids after the packer element is set. 